The Relae Blog

Key Takeaways

• The European Commission’s proposal to reform the EU Emissions Trading System (EU ETS) would fund 250 million tonnes of biogenic emissions capture with carbon storage (BioCCS) and direct air capture with carbon storage (DACCS), from 2031-2040. 
• Our modeling suggests that the Commission’s anticipated prices are unrealistically low, meaning revenue from auctioned ETS allowances may be insufficient to fund an equivalent volume of DACCS and BioCCS.
• The proposal would also fund the procurement of up to 260 million tonnes of high-quality international carbon credits from 2036-2040. This would turn the EU into a major buyer of credits under Article 6 of the Paris Agreement, and set eligibility standards that will shape demand beyond Europe.
• Negotiations are expected to conclude in early 2027 and will determine the procurement volumes, scope of eligible projects, design of funding mechanisms, and associated timelines. 
• Developers who design projects to meet demand and eligibility standards in both voluntary and compliance markets will be best placed to capture this value.

Voluntary and Compliance Markets Are Converging

Carbon project developers are already commercializing across voluntary and compliance markets. Eligible nature-based projects can sell credits to voluntary buyers or to CORSIA-obligated airlines. Similarly, ethanol plants paired with carbon capture and storage (CCS) can generate durable carbon dioxide removal (CDR) credits or monetize their low-carbon ethanol through California’s Low Carbon Fuel Standard. Corporate buyers are also guided by the Science Based Targets initiative’s (SBTi) Corporate Net Zero Standard, which introduces mandatory CDR from 2035. Increasingly, suppliers will need to consider both voluntary demand and compliance opportunities in order to maximize their economic benefits and climate impact. 

The European Commission’s proposal to integrate carbon credits into the EU Emissions Trading System (ETS) creates another significant opportunity. The proposal reshapes the ETS on several fronts. It expands airline obligations, extends incentives for sustainable aviation fuel (SAF), reforms price control levers, and attaches conditions to the distribution of free allowances. All of these reforms are under negotiation with the European Parliament and the Council of the EU, with a final agreement expected in the first quarter of 2027. This blog focuses on the two elements most relevant to carbon project developers: the integration of CDR, and the procurement of international credits.

What Is the EU Emissions Trading System?

The EU ETS is Europe’s flagship emissions trading scheme: a cap-and-trade carbon market covering power, industry, aviation, and maritime shipping. The EU ETS sets an overall cap on the emissions allowed from regulated sectors. Companies must hold one allowance for every tonne of CO₂ equivalent (tCO₂e) they emit, or face penalties. Most allowances are sold at auctions, and those funds are recycled back into climate and energy projects in Europe. The number of allowances issued decreases annually, which tightens supply, increases prices, and sharpens the incentive to decarbonize. However, driving those final emissions to zero can become prohibitively expensive. Integrating CDR into the ETS would allow entities to compensate for the residual emissions from the hardest-to-abate sectors with an equivalent volume of CDR. 

The European Climate Law and the 2040 Target

The European Climate Law sets a binding target to cut net emissions 90% below 1990 levels by 2040. The law lets international carbon credits cover “up to 5% of 1990 net Union emissions.” The baseline emissions were around 4,609 million tCO₂e, meaning 5% is roughly 230 million tCO₂e per year. The Commission’s proposal would replace a small share of mandated ETS emissions reductions with international credits, easing pressure on regulated entities while keeping the bulk of the effort (at least 85% reduction) at home.

The proposal now sits with the European Parliament and the Council of the EU, with members of each body working to reach consensus. Once each body has adopted a unified negotiating position, they will enter into ‘Trilogue’ negotiations alongside the Commission to agree on a final text. On current timelines, those talks will begin in early 2027.

Integration of CDR into the EU ETS

What Did the Commission Propose?

Scope: The proposal brings only biogenic emissions capture with carbon storage (BioCCS) and direct air capture with carbon storage (DACCS) credits into the ETS. As long expected, the proposal requires these units to be generated in the EU and certified under the Carbon Removal and Carbon Farming (CRCF) Regulation. The Commission chose to exclude all other project types, at least initially. The proposal does not indicate the relative procurement quantities of BioCCS and DACCS, but the Commission will pursue a portfolio approach that considers cost-effectiveness. 

Volume: The Commission would increase the ETS cap by a total of 250 million allowances, and use the additional auction revenue to fund the purchase of 250 million tCO₂e of CDR. If the initial funds are insufficient, revenue from an additional 10 million allowances would be set aside to fund these purchases. 

Mechanism: BioCCS facilities regulated under the ETS that generate their own CRCF-certified CDR can use the credits to reduce their ETS obligations. Otherwise, all procurement and use of units would be managed by a central procurement facility, not by regulated entities. This design differs from the approach promoted by the UK ETS Authority in 2025 (see Figure 1). This could be relevant in discussions about relinking the systems, as fungibility of CDR generated in the respective markets will be critical to developer planning.

Timeline: The Commission can start buying eligible CDR in 2031. The volume of allowances auctioned to fund this procurement will start in 2031 and increase each year, up to 48 million allowances in 2040. The level of procurement in earlier years was not included in the proposal. An important review clause is built in: in 2034, the Commission will assess whether evidence supports the integration of more project types, and also whether regulated entities can start buying CDR directly.

What’s Under Negotiation? 

Scope: Of all excluded project types, the Commission's accompanying Impact Assessment discussed biochar most favorably. Peter Liese, the European Parliament’s lead negotiator on ETS reform, initially proposed to include biochar, but capped at 20%, possibly to assuage concerns that biochar would crowd out DACCS and BioCCS due to its lower cost. Even if non-CCS CDR remains excluded for now, the final text could require new legislation to set criteria on how those projects can achieve integration in future.

Volume: Negotiators’ perspectives vary widely on the optimal volume of CDR to include in the ETS. The parliamentary Greens, more skeptical of increasing the ETS allowance cap to accommodate CDR, have proposed that the 250 million figure should be as low as 75 million. Conversely, Renew, a centrist party more supportive of CDR integration, wants to increase the figure to 300 million. In any case, specific procurement targets for all years, not only 2040, would improve market certainty and enhance project bankability. 

Mechanism: Revenue from auctioned ETS allowances may be insufficient to fund an equivalent volume of CDR. Our proprietary modeling, which draws on anonymized real-world price points by suppliers, suggests the Commission’s anticipated CDR prices are unrealistically low. Separately, Council representatives have proposed to set aside 50 million allowances in case the initial funding falls short, up from the Commission’s proposed 10 million. Other ETS aspects also play a role. For example, extended provision of free allowances would reduce auction demand and depress prices. Developers will want confirmation of how much CDR the Commission will buy, regardless of the ETS allowance price.

Timeline: Negotiators and industry advocates have called for the Commission to start procuring CDR well before 2031. The review considering inclusion of non-CCS project types could also be brought forward from 2034. Both of these aspects would enhance certainty for developers, and enable projects to reach Final Investment Decision (FID). 

EU Procurement of International Carbon Credits 

What Did the Commission Propose?

Volume: The European Climate Law allows the use of around 230 million tCO₂e of international credits per year. The European Commission proposed that the ETS use some of these credits–up to 260 million tCO₂e in total across 2036-2040. In total, this demand for Paris Agreement-aligned internationally transferred mitigation outcomes (ITMOs) would be greater than the 170-215 million tCO₂e projected for CORSIA Phase 1. Importantly, the ETS only represents a portion of the full amount of international credits available for EU entities to use. Rules governing how EU member states can use ITMOs to meet their climate targets are pending, and the allocation and use of those credits across EU climate policy instruments remain subject to further legislation.

Mechanism: The linear reduction factor (LRF), which sets the rate at which the issuance of new ETS allowances declines annually, would fall from 3.7% over 2031-2035 to 1.7% from 2036-2040, rather than the 2.7% that would otherwise apply. That one-point slowdown leaves more allowances in the system. Auction revenue from up to 260 million extra allowances would fund the purchase of an equivalent volume of high-quality international credits. Again, procurement would run through a Commission facility; regulated entities cannot buy credits directly.

Scope: Credits would need to meet criteria established under the Climate Law. A proposal is expected in late 2026, expected to make reference to standards under Article 6.4 of the Paris Agreement and impose additional requirements on the quality of the host country’s climate reporting. 

Timeline: Revenue from auctioned ETS allowances will be set aside for international credits from 2036 onwards. However, the European Climate Law provides for a pilot phase from 2031-2035, which could enable earlier activity from the Commission. A review in 2033 will determine if sufficient high-quality credits are available on the market—if there aren’t, the LRF will rise to 2.7%, closing the headroom opened for international credits.

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What’s Under Negotiation? 

Volume: The most important question is whether international credits survive the negotiations at all, with some influential parties concerned about replacing domestic emissions reductions driven by the ETS with projects outside of EU control. Parliamentary groups, members of the Council of the EU, and the European Economic and Social Committee, an EU advisory body, have all proposed that international credits be entirely excluded from the text.

Mechanism: Should international credits remain in scope, the Commission will be pushed to elaborate on expectations for the pilot period. Peter Liese’s proposal also suggested that international projects developed by EU-linked companies could be given priority. This could lead third-country governments to seek more European involvement in the development of carbon projects. Additionally, reporting on closed-door negotiations suggests that some parties want to connect international credits to the market stability reserve (MSR), which adjusts allowance supply in response to surplus in the market, and leave the LRF untouched.

Scope: The quality criteria for international credits will be laid out in separate legislation, and similar criteria may be applied to EU airlines meeting their CORSIA obligations. The Commission’s Climate Change Expert Group has already discussed meaningful restrictions, such as on projects related to avoided deforestation or based in countries with faulty reports under Article 6 of the Paris Agreement. These rules will be critical for stakeholders, as mere compliance with the rules of certification registries may not be enough to qualify a project for procurement eligibility.

Timeline: The review of the international credit market in 2033 leaves project developers little time to secure capital before procurement begins in 2036. The start date is fixed in the Climate Law, so it is not up for negotiation. However, the inflexible design of the fallback could change. As drafted, the LRF rises to the full 2.7% in 2036 if there are not enough available high-quality credits, meaning none can be used at all. Negotiators could instead use the volumes the market delivers, and scale the LRF to the remaining gap, rather than raising it in full.

Proposed EU ETS Timeline: Key Dates for CDR and International Credits

• Early 2027: Trilogue negotiations expected to begin, with a final agreement targeted for the first quarter.
• 2031: The Commission can begin buying CDR, and the pilot phase for international credits may be considered for 2031-2035.
• 2033: Review of whether enough high-quality international credits are available. If not, the LRF rises to 2.7% (in 2036-2040).
• 2034: Review of whether to admit more CDR project types and let regulated entities buy CDR directly.
• 2036: International credit procurement begins, and the LRF would fall to 1.7%.
• 2040: Allowances auctioned to fund CDR reach up to 48 million, and the 90% net emissions reduction target applies.

Positioning for What Comes Next 

However the final text lands, the EU is becoming a major player in the market for CDR and internationally transferred mitigation credits. Compliance demand will become increasingly important, and if you’re raising capital for a project, you should no longer plan around voluntary buyers alone. You need a clear view of the regulatory factors that decide project viability, including committed volumes, legislative timelines, eligibility rules, and allowance price controls. We help developers formulate cohesive strategies across voluntary and compliance markets, while building quality projects that deliver the committed tonnes and impact.

Frequently Asked Questions

Can companies use carbon dioxide removal or international credits for EU ETS compliance?

Under the European Commission proposal, the Commission buys both centrally, so regulated operators cannot surrender CDR units or international credits to meet their obligations. There is one exception: a regulated entity that generates its own biogenic emissions capture with carbon storage (BioCCS) credits certified under the Carbon Removal and Carbon Farming (CRCF) Regulation can use those to reduce its ETS obligations.

Which carbon dioxide removal pathway would be eligible under the EU ETS?

Only biogenic emissions capture with carbon storage (BioCCS) and direct air carbon capture and storage (DACCS). Both must be EU-based and certified under the Carbon Removal and Carbon Farming (CRCF) Regulation. Other CDR methods are excluded for now.

When would the EU start buying carbon dioxide removal and international credits?

The two run on different timelines. The European Commission could begin purchasing CDR from 2031, with volumes ramping up to 48 million tonnes of CO2 equivalent (tCO₂e) in 2040. Actual procurement volumes may depend on auction proceeds, removal costs, and the final mechanism design. International credit procurement would start in 2036.

Key Takeaways

• The EU Renewable Energy Directive (RED III) sets the sustainability rules behind clean fuel markets in Europe, and frameworks in the UK and US draw on it. Producers typically show compliance through certification schemes recognized by the European Commission, such as ISCC and RSB.
• Certification provides evidence that a fuel meets the regulatory minimum, but schemes apply RED differently, particularly on topics like social outcomes and leakage. As a result, two compliant fuels can differ in quality.
• Relae’s Criteria for High-Quality Low Carbon Fuels give buyers a single benchmark for assessing quality beyond compliance. By comparing a producer’s certificate against the criteria, buyers can identify gaps and develop contract provisions on quality areas the certificate does not cover, tailored to their own priorities. This can help buyers identify and manage quality risk and stay ahead of tighter regulations likely to come under RED IV.

RED Sets the Bar for Clean Fuels in Europe and Beyond

RED III is a key regulatory framework governing sustainability requirements for clean fuels. Its sustainability criteria underpin Europe’s clean fuels markets, including sustainable aviation fuel (SAF) under ReFuelEU Aviation, marine biofuels under FuelEU Maritime, and biomethane injected into Europe’s gas grid. Its reach extends beyond the EU, too. The UK Renewable Transport Fuel Obligation and SAF Mandate apply sustainability criteria modeled on RED, and the certification schemes built around RED will play a role in California’s new feedstock sustainability requirements under its Low Carbon Fuel Standard.

A Certificate Confirms Compliance, Not Quality

Low-carbon fuel producers typically demonstrate compliance with RED through voluntary certification schemes recognized by the European Commission, such as the International Sustainability & Carbon Certification (ISCC) and the Roundtable on Sustainable Biomaterials (RSB). A certificate provides evidence that a fuel clears the regulatory bar. Every recognized certification scheme covers RED’s core requirements, but each applies them differently, and some go further than others.

How Certification Schemes Can Differ

Certification schemes tend to differ most on questions RED only partly addresses. Social outcomes are one example. RED largely requires certified producers to comply with the laws of the country where the feedstock is grown or the fuel is produced. Following local law, however, is not the same as paying living wages, respecting land rights, or delivering benefits to nearby communities, especially where local protections are weaker than the EU’s. Some schemes fill that gap with their own social requirements; and others do less. 

Leakage is another example. It refers to emissions a fuel causes outside its own supply chain, which its carbon intensity does not reflect. One common form is indirect land-use change (ILUC). When cropland or feedstock is redirected to fuel production, the food, feed, or other uses it previously supplied still need to be met elsewhere. That can push cropland expansion into forests or grasslands, releasing the carbon they store. RED manages this risk by limiting the use of feedstocks most associated with expansion into high-carbon-stock land. However, RED acknowledges that ILUC is not limited to these high-risk feedstocks, and diverting waste feedstocks from existing uses can have similar knock-on effects. Without asking specific questions about a given producer’s supply chain, buyers may have limited visibility into the leakage risk behind the fuel they buy.

These examples show that, on paper, two RED-compliant fuels can look the same while differing significantly in overall quality. One reason is that they can be certified under schemes with different requirements on issues such as social outcomes. Another is that RED is built to work at scale, applying a consistent set of rules across the whole market. That consistency is a strength, but it means that some issues, such as leakage, are addressed at the system level rather than for each individual fuel. For buyers, the certificate is a useful starting point for offtake conversations, but may not be enough on its own to judge the quality of what they are buying.

Assessing Quality Beyond Compliance

So how can a buyer tell whether one certified fuel is higher quality than another? Today, doing so means comparing certification schemes rule-by-rule, which is cumbersome. Relae’s Criteria for High-Quality Low Carbon Fuels provides a shared definition for what “better than compliant” means. It brings together requirements from RED, CORSIA, ISCC, RSB, national SAF mandates, and other frameworks into a single benchmark, and adds criteria on social outcomes, additionality, and leakage. We built the criteria for voluntary buyers, but they are just as useful for regulated companies that want to go beyond meeting their mandates and show how well they do it.

How Buyers Can Apply the Criteria, and How Relae Can Help

In practice, buyers can use Relae’s criteria in four steps. Each one calls for technical judgment on scheme rules, supply chains, and contract terms. Relae’s fuels team works alongside buyers at every stage, from the first certificate review to the final offtake terms.

1. Start with the certificate. Confirm which scheme the fuel is certified under, what the certificate covers, and whether the producer holds any optional add-ons, such as a low ILUC risk certification. Our team reviews certificates and the scheme rules behind them to confirm what is and is not covered.
2. Map the certificate against Relae’s quality criteria. Sort each criterion into what the certificate already covers, what it partly covers, and what it does not address. Our experts carry out this mapping for a specific fuel and pathway and highlight the gaps that matter most.
3. Ask the producer to fill the gaps. Turn each gap into a direct question, for example, how the producer verifies wages and land rights in its supply chain, or how it manages ILUC risk. The answers help buyers see where quality risks may lie that compliance alone does not cover. We help prepare these questions and assess the producer’s responses and evidence.
4. Build the answers into an offtake agreement. Use the answers to develop contract provisions on quality that the certification does not cover, such as additional verification, disclosure, or feedstock-sourcing requirements. These provisions help buyers manage quality risks over the life of the deal, whether it’s a SAF offtake agreement or another fuel supply contract, and support the sustainability claims they make about the fuel. Our fuels experts work with buyers and their counsel to shape these provisions.

Procuring for Where Standards Are Heading

The criteria are also a guide to what may come next. The European Commission is preparing its post-2030 renewable energy framework (RED IV). The Commission held a public consultation from March to June 2026, and plans to propose legislation by the end of the year. The final scope is not yet known, but industry submissions point to areas where bioenergy rules could tighten, such as stricter traceability and on-site audits for imported waste feedstocks. Buyers who procure against where standards are heading, not just today’s minimum, will be less exposed when the rules change and better able to back up the sustainability claims they make about their fuel.

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Frequently Asked Questions

What is RED III?

RED III is the current version of the EU Renewable Energy Directive. It sets renewable energy targets and the sustainability criteria that biofuels, biogas, and other renewable fuels must meet to count under EU regulations. Those criteria apply across Europe’s clean fuel markets, including SAF under ReFuelEU Aviation and marine fuels under FuelEU Maritime.

How do producers show their fuel complies with RED?

Most producers use a voluntary certification scheme recognized by the European Commission, such as ISCC or RSB. The scheme audits the producer and its supply chain against RED’s requirements and issues a certificate if they are met. 

Are all RED-recognized certification schemes the same?

No. Every recognized scheme covers RED’s core requirements, but each applies them differently, and some add requirements or optional add-ons of their own. Certification schemes differ the most on issues RED only partly addresses, such as social outcomes and leakage. As a result, two RED-compliant fuels can differ in overall quality.

Who should use the Relae Criteria for High-Quality Low Carbon Fuels?

We designed the Criteria for High-Quality Low Carbon Fuels for voluntary buyers, but they are equally useful for regulated companies. Buyers can compare a producer’s certificate against the criteria to find gaps, raise those gaps in offtake discussions, and address them through contract provisions. Relae works with both voluntary and compliance buyers to apply the criteria to specific fuels and deals, from assessing producers to shaping offtake terms.

What is RED IV, and why does it matter for buyers today?

RED IV is the post-2030 renewable energy framework the European Commission is preparing. The Commission consulted on it from March to June 2026, and plans to propose legislation by the end of 2026. Sustainability rules for bioenergy could tighten. Buyers who procure against where standards are heading, rather than today’s minimum, will be less exposed when the rules change.

Key Takeaways

• Carbon credits are one of several instruments for decarbonizing cement, alongside environmental attribute certificates (EACs) and direct procurement of lower-carbon products. Each serves a different purpose, and buyers and developers should understand how they interact before engaging. 
• Article 6.4 of the Paris Agreement is becoming a reference point for public and private carbon credit procurement, so the quality of its methodologies now holds significant weight. 
• Proposed methodology A6.4-PMM010 - Partial substitution of fossil fuels by MSW in cement manufacture largely aligns with Relae and Microsoft’s Criteria for High-Quality EACs in the Concrete and Steel Sectors. However, Relae identified opportunities to strengthen provisions addressing interactions between carbon credits and environmental product declaration (EDP), where credited reductions are deducted from the product's EPD, with the aim of reducing the risk of the same mitigation being claimed more than once.

Article 6.4 Joins the Cement Decarbonization Toolkit 

Article 6.4 of the Paris Agreement is expanding the financing options for decarbonizing cement and concrete. Environmental attribute certificates (EACs) let buyers pay for lower-carbon production without taking physical delivery of the product, while carbon credit methodologies reward manufacturers for storing captured CO₂ in their products. 

Relae is actively shaping this market: conducting technical diligence for buyers of cement EACs, providing project assurance and go-to-market support for industrial decarbonization projects, and leading market development through the publication of the Criteria for High-Quality EACs in the Concrete and Steel Sectors, in collaboration with Microsoft. 

To build on these efforts, Relae (as Carbon Direct) recently participated in the public consultation for a proposed carbon credit methodology under the Paris Agreement Crediting Mechanism (PACM). Methodology A6.4-PMM010 would credit emissions reductions from replacing fossil fuels with municipal solid waste (MSW) in the production of cement clinker. The approach was proposed by the Inter-American Cement Federation (FICEM), which in 2026 partnered with the UN Industrial Development Organization to work to decarbonize the sector across Latin America. 

The PACM, established under Article 6.4 of the Paris Agreement, could underpin national climate strategies and voluntary offsetting demand for years to come. One potential avenue of influence is the SBTi Corporate Net Zero Standard V2.0, which has introduced formal recognition of market-based instruments. As both public and private entities weigh their carbon credit procurement options, this is a critical juncture for getting the methodologies right. 

Two Key Options for Decarbonizing Cement: Carbon Credits and EACs

Concrete and steel are indispensable to modern construction and together account for approximately 13% of global CO₂ emissions. With demand for infrastructure continuing to rise, including via data centers, decarbonizing these sectors is essential for new construction to remain consistent with climate commitments. 

Carbon credits are one route to financing that work. A credit is issued for each tonne of emissions reduced below a baseline, meaning the emissions that would have occurred without the intervention. For a cement plant, credits might be issued for switching to low-carbon fuels or installing new equipment that reduces emissions. Companies buy credits to offset emissions outside their own value chains, and in doing so channel finance to projects that would not otherwise proceed. 

EACs are a second route, and one that Relae is helping to shape. An EAC assigns a measured environmental characteristic to a unit of product (e.g., tonnes of CO₂ per tonne of cement), usually established through an attributional life cycle assessment. The buyer pays for the lower-carbon attribute of a product and reports it against its own value chain emissions, which makes EACs a tool for scope 3 decarbonization rather than for offsetting. 

While methodology A6.4-PMM010 is for carbon credits, we use the Relae EAC criteria as our reference point, as both instruments depend on the same foundations. An intervention must be traceable to a specific facility, the carbon impact must be quantifiable with a defensible method, and the project must be assessed for its social and environmental harms and benefits. The criteria set out in depth how Relae tests those foundations for an EAC claim, and the same tests apply with little adjustment to a crediting methodology.

Regardless of the preferred market instrument, replacing fossil fuels in cement production should be read as a partial solution. Kiln fuel combustion accounts for roughly 35% of the CO₂ emitted in clinker production, while the remaining 65% arises from process emissions inherent to calcination: when the heated limestone breaks down into lime and releases CO₂ as a byproduct. As such, Relae considers this as part of a multi-step decarbonization strategy that should ultimately address calcination emissions through carbon capture, novel binders, or substitution of the clinker itself. 

Why the PACM Matters for Carbon Credit Buyers

While there is a lack of supply today, PACM credits have the potential to underpin carbon credit demand. Corporate buyers looking to make recognized offsetting claims have reason to favor units issued under a government-endorsed UNFCCC mechanism. The European Climate Law references Article 6.4 quality standards, and the EU is expected to tie the eligibility of procured international credits to its methodologies. The German federal government has used UN-recognized credits to offset its business travel emissions since 2014, and UK government agencies have also sought PACM credits to fulfill their offsetting needs. 

A strength of the PACM is its centralized structure. The 12-person Supervisory Body (SB) makes all final approvals, following methodology recommendations from the Methodological Expert Panel (MEP). All methodologies draw on the same Article 6.4 standards and tools. For example, A6.4-PMM010 relies heavily on the Standard on Baselines and the Tool on Emissions from Solid Waste Disposal Sites. Together, these can be used to calculate the counterfactual emissions from waste diverted from landfill, and dictate how to monitor waste conditions over the crediting period.

The potential for the PACM to scale is conditional. As the market matures, voluntary buyers can choose from a widening range of high-quality carbon credits. Moreover, the European Commission has shown, via its criticism of CORSIA, that the EU will make robust efforts to prohibit procurement from projects it considers flawed. As such, the PACM will only succeed if it provides compelling methodologies to accompany solid governance. That is the standard against which Relae reviewed the fossil fuel substitution methodology.

Relae’s Response to the Cement Methodology A6.4-PMM010 

Alignment With Our High-Quality Criteria

We found methodology A6.4-PMM010 for carbon credits to largely align with our high-quality criteria. Certain gaps in the methodology are addressed by the Article 6.4 standards and tools it references, and the combination provides additional safeguards intended to support robust integrity. 

In both the methodology and our criteria, additionality must be shown on regulatory, financial, and common practice grounds. Crediting is limited to the capacity installed at validation, so carbon finance improves existing production rather than funding new clinker capacity, which aligns with our catalytic impact criterion. The methodology also credits both displaced fossil fuel and avoided landfill methane, a dual benefit that strengthens the case for these projects, especially where landfill sites are poorly managed (e.g., do not flare methane). 

We proposed only two major refinements: updating the landfill methane baseline at each verification, and closing the double-counting gap with environmental product declarations (EPDs). 

Landfill Methane Baseline

Under Article 6.4, an independent verifier checks a project’s reported results for each monitoring period before new credits are issued. Relae proposed that the landfill methane baseline be re-established at each of these verifications: from site measurements where available, and by re-selecting the default value to match current conditions where they are not. 

The baseline rests on two factors that can shift as a waste disposal site is capped, compacted, or drained: the oxidation factor (the share of methane absorbed by landfill cover before release), and the methane correction factor (how much of the waste decomposes without oxygen). 

The Article 6.4 Tool on Emissions from Solid Waste Disposal Sites offers measured and default routes for setting these values, but the methodology does not specify which applies. A project developer could apply default values from the tool and leave them static for the whole crediting period. Re-selecting those values at each verification, rather than locking them in at the outset, keeps the baseline tied to how the site is actually performing throughout its crediting period.

Double-Counting Concerns

The Article 6.4 Activity Standard rightly requires that issued credits do not overlap with other emissions mitigation crediting schemes. However, the A6.4-PMM010 does not explicitly say how that applies to EPDs, which report a cement product's carbon intensity. Relae proposed closing that gap directly: the EPD should report the new, lower carbon intensity achieved after the intervention without subtracting the avoided emissions again. The methodology should also require an annual declaration confirming that the credit and the EPD aren’t claiming the same reduction twice. 

An EPD reports a cement product’s carbon intensity, so a lower-carbon cement can earn value in two places at once: through the carbon credit, and through the EPD itself, which is exactly where the double-counting risk sits. EPD standards already keep the avoided emissions out of a product’s carbon intensity, reporting them separately from the product’s life-cycle stages, but A6.4-PMM010 never references that separation. 

Explicitly addressing this distinction in the methodology, and pairing it with Relae’s proposed annual declaration, could strengthen transparency and reduce the risk of overlapping claims associated with the same emissions reductions, where the same emissions reduction can’t be claimed once through the credit and again through the product’s own carbon footprint.

How Relae Can Help

A6.4-PMM010 is a well-designed methodology, but market-based mechanisms for enabling cement decarbonization are evolving faster than practical guidance on how to use them credibly. Relae works with buyers and cement producers navigating this landscape. For buyers, we conduct technical due diligence, advise on procurement strategy, and guide robust claims. For producers and project developers, we assess which market-based mechanism suits a given plant and provide the analytical, market intelligence, and go-to-market support needed to monetize the chosen mechanisms credibly.

Frequently Asked Questions 

What is the difference between a carbon credit and an Environmental Attribute Certificate (EAC)?

A carbon credit represents one tonne of emissions reduced below a baseline, and a buyer uses it to offset emissions outside their value chain. An EAC attaches a measured carbon attribute to a unit of product, such as cement, which the buyer reports against its own scope 3 emissions rather than for offsetting.

What is the relationship between Article 6.4 of the Paris Agreement and the Paris Agreement Crediting Mechanism (PACM)?

Article 6.4 of the Paris Agreement establishes the PACM, which refers to the registry itself along with the methodologies, standards, and tools that govern the credits listed on it. Article 6.4 is the treaty provision, and PACM is the mechanism built under it, so people often use the two terms interchangeably.

How do PACM credits differ from other credits available on the voluntary carbon market (VCM)?

PACM methodologies and standards are developed through a transparent UNFCCC process, which sets them apart from most VCM credits. This does not make PACM credits inherently higher quality, but some buyers, especially governments, prefer to tie procurement to PACM standards. Another key difference is that 7% of PACM credits are deducted at issuance–5% are transferred to the UN Adaptation Fund, and 2% are cancelled for overall mitigation.

Key Takeaways

• The Nasdaq Carbon Issuance Calendar, a new data platform, provides carbon removal buyers and suppliers with standardized information on future offtake availability, indicative pricing, and project maturity. The platform was developed in collaboration with Relae, formerly Carbon Direct.
• The Carbon Issuance Calendar addresses the fragmentation and transparency problems of the voluntary carbon market by centralizing standardized project data and embedding our scientific diligence framework, built over 900 project reviews, giving buyers delivery-risk insight that no registry or marketplace offers today.
• The Carbon Issuance Calendar is an important early step, not the whole journey: it shows buyers what durable tonnes exist and allows them to compare projects with apples-to-apples data. 
• Buyers can move from the Carbon Issuance Calendar into technical diligence, contracting, and project assurance with Relae’s advisory team. Suppliers can register to connect with buyers who are ready to engage.

Carbon Removal Project Data Has a Visibility Problem

If you're sourcing durable carbon removal credits, you may run into a familiar wall: project data scattered across dozens of developer websites, presented in inconsistent formats, with no easy way to compare one project against another. If you're a project developer, you face the mirror image of that problem: fielding individual requests for proposals, with no central place to showcase your available tonnes.

Get this wrong, and buyers may end up counting on carbon removal that never shows up - the delivery risk bugbear.

Between 2022 and 2024, high-durability engineered carbon removal made up just 2 percent of all carbon credit issuances. They remain in short supply, particularly the high-quality supply corporate buyers need. The gap is set to widen: our 2026 State of the Voluntary Carbon Market report found that more than 80% of the 2030 high-durability carbon removal projects are at risk of stalling and failing without additional offtake and financing commitments.

The Nasdaq Carbon Issuance Calendar, developed by Nasdaq in collaboration with Relae, offers an important first step toward addressing this information gap.

What Is the Nasdaq Carbon Issuance Calendar?

The Carbon Issuance Calendar is a centralized, accessible dashboard where carbon removal buyers and suppliers view standardized project data: future credit availability, indicative pricing, and project delivery status, all in one place. 

The Nasdaq Carbon Issuance Calendar combines structured, developer-provided project data with project maturity assessment informed by Relae’s assessment framework and technical diligence. This helps users understand future CDR availability, indicative pricing, and potential project delivery risk through a single platform.

This expertise didn't appear overnight. It comes from sitting across the table with developers, stress-testing their science, mapping their delivery timelines against reality, and helping them show up to buyers as credible partners. The result is a track record that gives the framework embedded in the Carbon Issuance Calendar its depth. It's a starting point, built for buyers and suppliers to find each other on the basis of consistent, comparable information, using international class financial and information infrastructure.

How Buyers Should Use the Nasdaq Carbon Issuance Calendar

Today, if you're trying to procure durable carbon removal credits, you have no single place to start. You have to visit individual developer sites, request information through scattered channels, and compare projects that present data in entirely different formats before diligence has even begun. In many cases, you are comparing apples to oranges - different kinds of CDR projects with different durabilities, risks, and overall quality. 

The Carbon Issuance Calendar provides a central starting point. You can view future credit availability, compare indicative pricing across projects, and begin assessing options without contacting each supplier one by one.

More importantly, the Carbon Issuance Calendar frames the data. Our scientists developed a delivery-oriented lens, built from reviewing over 900 carbon removal projects, drawing on the same rigor behind our Criteria for High-Quality Carbon Dioxide Removal, which we develop annually with Microsoft.

How Suppliers Reach Buyers Through the Carbon Issuance Calendar

If you're a project developer, the Nasdaq Carbon Issuance Calendar tackles visibility, one of the most persistent barriers to market access. You can list available tonnes, display indicative pricing, and reach a global audience of corporate and financial buyers at no cost.

The timing matters. Many first-of-a-kind engineered carbon removal projects are preparing to break ground and need bankable offtake agreements to secure financing before they can do so (a key aspect of CDR 2.0). Our analysis of approximately 140 high-durability carbon removal project developers found scale-up plans for 30 million tonnes of supply per year. Reaching that potential will take real demand: committed forward offtake, increased project equity investment, and access to lending. 

Register now: you'll be positioned to connect to buyers actively looking to engage.

How Does the Carbon Issuance Calendar Differ From a Carbon Credit Registry or Carbon Removal Marketplace?

The Carbon Issuance Calendar solves a distinct, early-stage problem. It gives buyers and suppliers a centralized place to find each other and compare options against standardized information, something neither a registry nor a marketplace is built to do.

For a closer look at how registries differ and what you should weigh when navigating them, read our Navigating Carbon Credit Registries report.

Scientific Diligence Turns Visibility Into Confidence

Standardized data tells you what exists. Scientific diligence tells you what's worth pursuing. 

Relae’s scientists do that work every day. Our experts apply rigorous pathway-specific criteria to live projects, evaluating delivery risk and status, and identifying where questions remain is the core of what we bring to the carbon removal market.

The Carbon Issuance Calendar puts an accessible version of that expertise at the top of the procurement funnel. It’s for everyone in the market - you don't need to be a carbon removal scientist to use it. This snapshot allows you to compare projects against each other, giving you a meaningful starting point before deeper diligence begins. 

Want to go deeper on a specific project? Relae’s technical diligence team picks up right where the Carbon Issuance Calendar leaves off.

What Carbon Removal Projects Are on the Carbon Issuance Calendar Today?

The Carbon Issuance Calendar currently features engineered and hybrid carbon removal projects: direct air capture, biochar, enhanced rock weathering, and bioenergy with carbon capture and storage. These high-durability pathways offer permanence on the order of hundreds to thousands of years.

Many of these projects are at an inflection point: they’re ready to scale but dependent on committed offtake to unlock financing. The Calendar serves their needs, and the buyer’s needs, together.

Nature-based carbon removals have their own criteria and market dynamics. They may appear in a separate segment of the Carbon Issuance Calendar down the line.

From the Carbon Issuance Calendar to Completed Carbon Removal Procurement

If you're building or refining a carbon removal procurement strategy, the Carbon Issuance Calendar is the right place to start. 

From there, you can choose to work with the Relae advisory team to support every later stage: technical diligence on specific projects, contracting and negotiation support, ongoing project assurance, and access to curated carbon credit sourcing. The Carbon Issuance Calendar surfaces the market; we help you navigate it, connecting you with the right developers, on the right terms, with the scientific confidence to move forward.

Moving from commitment to delivery takes structural change across the market, too—our CDR 2.0 white paper lays out the five pillars we see as essential to getting engineered and hybrid carbon removal projects built and delivering.

Key Takeaways

1. The decision to fund a project is determined by a holistic review of project development maturity. This applies across capital-intensive projects, including low-carbon power generation, carbon capture and storage (CCS) solutions, sustainable aviation fuel (SAF), and broader transition infrastructure build-out. Both technical and commercial workstreams must be developed in parallel to avoid project failure. 
2. Early scope decisions, such as site selection, core technology selection, and nameplate capacity, are cheap to make but become exponentially disruptive and costly to reverse. 
3. Independent challenge and verification is tangible evidence of a disciplined, well-managed capital development process. 

Bridging the Gap from Announcement to Delivery

Among project developers, a perception often persists: seeking external review signals a project in distress. In capital budgeting discussions, subjecting engineering scope and commercial assumptions to third-party interrogation can be misconstrued as a vote of no confidence in the primary delivery team.

In reality, the reverse is true. Across complex infrastructure, independent challenge is the disciplined stage-gate practice that protects capital by reconciling technical reality with commercial terms before designs are locked.

Independent Challenge Is a Sign of Strength, Not Doubt 

Across capital projects, and in particular within emerging low-carbon industrial infrastructure, the gap between announced projects and delivered assets remains stark. Data from the Mission Possible Partnership’s Global Project Tracker reveals that fewer than 17% of announced commercial-scale clean industrial facilities worldwide have reached Final Investment Decision (FID) or commercial operations, leaving more than 800 major decarbonization projects stalled in front-end development.

The causes of developmental paralysis are multifaceted. While macroeconomic interest rate shifts and global supply chain disruptions sit largely outside a developer's control, project definition and developmental discipline remain entirely manageable. Even amid external volatility, a project designed with resilience will have a far greater likelihood of success.

Independent review and assurance directly strengthen a project’s chance of success and overall value. Large global project delivery organizations have applied this discipline for decades by deploying independent teams to evaluate project readiness at every stage gate. For teams lacking a dedicated internal oversight organization, or those deploying first-of-a-kind facilities, third-party independent review provides the necessary rigor to facilitate project success.

Relae’s (formerly Carbon Direct) work with Stockholm Exergi is a clear example: independent assurance helped build funder and regulator confidence in a first-of-a-kind carbon removal facility with no direct precedent to benchmark against.

Why Projects Stall Between Announcement and FID 

Low-carbon infrastructure and net-zero industrial projects carry unique risks compared to the repeat delivery of established designs. Exciting new developments run a higher risk of falling victim to optimism bias or compressing development timelines to meet public announcement milestones.

It is a natural human tendency for project champions to focus on the upside during early development. However, early momentum must be balanced with processes that reintroduce industrial lessons, supply-chain realities, and operational resilience.

Front-End Loading (FEL) is a well-evidenced approach for improving capital project outcomes. Decades of benchmarking by Independent Project Analysis (IPA) show that approximately two-thirds of industrial megaprojects suffer capital cost overruns or schedule slippage of 25% or more, or encounter severe operational problems lasting more than two years post-startup. This pattern is repeating in low-carbon infrastructure: IPA’s analysis of 12 completed low-carbon projects found average cost escalation of 31% and schedule slip of almost 50%. Rigorous front-end definition remains the single strongest predictor of whether a project will achieve its cost and schedule targets. 

As highlighted in the CDR 2.0: Five Pillars of Successful Project Deployment and Delivery report published by Relae, projects falter when developers push ahead without stress-testing the full delivery framework. Stage gate reviews are the mechanisms that evaluate the total project concept and underlying business case. They are most effective when executed as independent cold-eye evaluations prior to each funding gate, identifying and mitigating vulnerabilities long before final investment decisions are reached. 

What Funders Need to See at Each Gate 

Different stages of project development rely on distinct capital sources, each requiring specific proof points before deploying funds.

Before FEED Funding: Justifying the Engineering Spend

Front-End Engineering Design (FEED) is a major financial commitment, typically costing between 2% and 4% of total project capital cost. The funders backing this stage are usually the developer’s own balance sheet equity, strategic partners, or public grant programs. Before allocating millions of dollars to detailed engineering, these funders need confidence on the fundamentals:

• A technically sound process concept, confirmed utility balances, and an energy integration scheme that fits the site.
• Secured site control, clear zoning pathways, and no environmental fatal flaws that could derail permitting.
• Documented availability of required feedstocks, water and power, paired with demonstrable interest from target off-takers.

Before FID: Proving Bankability and Commercial Closure

As a project approaches FID, the funding audience shifts to conservative commercial lenders, infrastructure funds, and binding offtake counterparties. These capital providers are not underwriting strategic vision; they are underwriting long-term operational cash flows and debt service. Depending on the project and financing structure, capital providers may require:

• A high-confidence capital cost estimate (AACE Class 2 or Class 3) backed by frozen Piping and Instrumentation Diagrams (P&IDs), firm equipment quotes, and a realistic execution schedule with clear critical paths.
• Bankable engineering, procurement, and construction (EPC) structures that clearly allocate risk, include performance guarantees and enforceable liquidated damages.
• Fully executed, binding offtake and feedstock agreements, along with non-appealable permits and completed utility interconnection agreements, with remaining conditions clearly understood.
• An objective, third-party challenge review that assesses operational viability and distinguishes an executable engineering plan from an aspirational concept.

Commercial and Technical Co-Development: The Stage-Gate Method in Practice

A project rarely fails because of an isolated mechanical issue or a purely commercial misstep; failure happens when technical decisions and commercial terms are negotiated in silos and decisions are made without understanding of the wider implications. 

We see this disconnect play out in several ways, including: 

• Sizing capacity before testing market demand: An engineering team may size a facility to maximize thermodynamic efficiency and economies of scale, only for the commercial team to discover buyers will only commit to half that volume. The developer is left with an oversized, unbankable design requiring fundamental rework. 
• Setting product specifications before negotiating offtake: Process engineers frequently design systems around standard vendor packages. However, when downstream transport, processing, or storage networks enforce strict purity standards, the facility faces costly equipment redesigns. This issue has materialized directly within European CCS networks. Open-access offshore storage operators, such as Norway's Northern Lights project, established strict cross-border CO₂ specifications requiring tighter moisture and impurity thresholds than originally designed for. 
• Locking Electrical Loads Prior to Interconnection Verification: As detailed in Relae’s analysis of physical infrastructure bottlenecks, scale is rarely constrained by capital availability; it is dictated by electrical transmission queues, substation headroom, and 24/7 firm power availability. Freezing electrical demand before verifying utility interconnection timelines risks stranding engineering work on an asset that cannot connect to the grid. 

How Relae Stress Tests Projects at Each Gate 

Independent reviews at each stage-gate improve success rates by stress-testing assumptions before presenting to lenders, infrastructure investors, or corporate buyers. Relae reviews projects across five categories using the TECOP framework:

• Technical: Verifying technology readiness levels (TRL), mass and energy balances, plot plan constructability, and operational availability under real-world conditions.
• Economic: Capex benchmarking, operating contingency adequacy, utility tariff sensitivities, and financial model cash-flow resilience.
• Commercial: Offtake agreement structures, feedstock contracts, contracting boundaries, EPC contract structures, and counterparty creditworthiness.
• Organizational: Owner's team capabilities, internal stage-gate governance, contractor oversight mechanisms, and execution capabilities. 
• Political: Statutory permitting status, regulatory durability, carbon market policy exposure, and local community social license.

The TECOP framework is relevant for evaluating delivery risk across all project types, see more in Relae’s Criteria for High-Quality Carbon Dioxide Removal, Delivery Risk Appendix.

What makes this approach effective is sitting on both sides of the table. Having completed over 250 deep-dive technology reviews, 900+ project evaluations, and advised on more than $6 billion in industrial project finance, Relae has extensive experience evaluating the considerations important to institutional funders and buyers.

The Value of Early Independent Project AssuranceIncorporating independent review should be standard practice for modern infrastructure delivery. Because funders will perform their own rigorous diligence regardless, conducting an independent evaluation early enables developers to address vulnerabilities proactively and present a more resilient business case.

Commissioning an independent team for a cold-eye review during early project formation can be a  cost-effective way to identify potential risks before they become expensive to address. Catching an unworkable process assumption, an oversized capacity plan, or a misaligned commercial interface during pre-FEED costs a tiny fraction of what it takes to fix those issues during construction

Ultimately, independent challenge is not an admission of doubt, but the disciplined stage-gate practice that protects capital by reconciling technical reality with commercial terms before designs are locked, signaling to partners, and your future funders that your project is built to deliver. 

To dive deeper into the frameworks that support successful projects, read Relae's white paper: CDR 2.0: Five Pillars of Successful Project Deployment and Delivery and take a look at project assurance in action through our Stockholm Exergi Case Study.

Frequently Asked Questions

What is independent project assurance?

Independent project assurance is a structured review of a capital project by a team that sits outside the project’s delivery organization. Reviewers test the engineering scope, cost estimate, schedule, commercial agreements and permitting position against what funders will require at the next stage gate. The developer receives a clear list of gaps, risks and proposed mitigations prior to presenting the project to lenders, investors or buyers.

When should a developer commission an independent project review?

Periodically throughout the project development process - at a minimum before each major funding gate, but smaller reviews are also beneficial at earlier stages when key concept and technology decisions are being made. A review before Front-End Engineering Design (FEED) tests whether the process concept, site and supply of feedstock, water and power justify the engineering spend. A review before Final Investment Decision (FID) tests whether the cost estimate, EPC structure and binding agreements will satisfy lenders. Site, technology and capacity decisions are cheap to change in pre-FEED and expensive to reverse once detailed engineering starts.

What does an independent project review assess?

Relae structures its reviews around the TECOP framework, which covers five risk areas: technical (technology readiness, mass and energy balances, constructability), economic (capex benchmarking, contingency, financial model resilience), commercial (offtake, feedstock and EPC contracts), organizational (owner’s team capability and stage-gate governance) and political (permitting, regulatory durability and social license). Reviewers also check that technical and commercial decisions are aligned, because projects often fail where the two are developed in silos.

How does an independent project review differ from lender due diligence?

An independent project review applies a holistic approach identifying not only gaps, but also opportunities to add value and strengthen the business case. Lender and investor due diligence is often purely looking at risks and gaps, prior to committing capital. Lender diligence protects the funder and reports its findings at a point when changes are costly and can delay financial close. A developer-commissioned review takes place earlier, so the project team can fix weaknesses in scope, cost or contracts before funders see them.

Key Takeaways

• Relae (formerly Carbon Direct) has conducted over 900 comprehensive, rigorous reviews of carbon removal (CDR) projects around the world. But fewer than 10% meet our standard for high-quality. In today’s market, scientifically-credible CDR supply is scarce.
• To identify high-quality projects, buyers and investors previously had to commission numerous deep diligences, which often made it a lengthy and complex process, not well-suited to most market participants. 
• The Diligence Collection changes that paradigm by giving you direct access to existing comprehensive analysis on a curated set of high-quality CDR projects. The hard work of identifying high-quality projects is already done, allowing you to move faster, spend less, and procure with more confidence.

Relae Sets the Bar for High-Quality CDR

Since 2020, every year Relae has released an updated version of the Criteria for High-Quality Carbon Dioxide Removal in collaboration with Microsoft. The Criteria set the standard for scientific rigor across nine CDR pathways and across six technical dimensions. Using this standard, the Relae team has conducted diligence on over 900 CDR projects across 63 countries. Our diligence has been used for over 50% of all tonnes contracted through announced CDR offtake agreements worldwide, including diligence for the majority  of tonnes from Microsoft’s announced offtakes. This gives Relae a uniquely deep understanding of the CDR market; and importantly, it has highlighted that high-quality projects in the voluntary carbon market are scarce. 

Quality Is the Central Challenge in CDR Procurement 

Only 10% of the projects that Relae has assessed meet our high-quality criteria. This means that without rigorous, scientific assessment, buyers and investors run real risk of exposing themselves to delivery shortfalls, financial loss, and reputational damage. 

This presents a series of challenges to buyers and investors interested in procuring or investing in CDR. Conducting diligence on CDR projects is time-intensive, complex, and requires deep expertise. Building the internal capacity to rigorously evaluate a wide variety of CDR projects isn’t practical for most actors. But conducting the in-depth diligence required to procure or invest confidently requires real commitment, especially when a significant proportion of the projects diligenced may not be high-quality. Finding the needle in the CDR haystack isn’t easy.

The Case for Curated CDR 

The Diligence Collection directly addresses these challenges by providing self-serve access to diligence on a curated set of high-quality CDR projects vetted by Relae. Every project has already been evaluated against the Criteria for High-Quality Carbon Dioxide Removal, the science-based benchmark jointly established by Relae in collaboration with Microsoft. The Collection includes projects reviewed on behalf of Microsoft and other major buyers, and more broadly reflects our diligence work across the market.

With the Diligence Collection, you're not starting from scratch. Instead, you're starting from a shortlist of some of the highest-quality CDR opportunities available, with robust scientific diligence to back them up. The bottleneck that's slowed procurement for so many organizations is no longer a concern.

The Collection offers two levels of diligence, matched to the level of scrutiny your commitment warrants:

1. Desk review: An executive-level assessment using available project documentation, enough to make an informed shortlisting decision or purchase.
2. Deep diligence: A comprehensive technical evaluation covering project design, operational risk, technology assessment, policy landscape, and community impacts, reflecting the same methodology that's informed the procurement programs of Microsoft and other major buyers.

Both tiers include the option to commission an updated evaluation as your needs evolve.

What Rigorous CDR Diligence Involves 

The depth of Relae’s diligence sets the Diligence Collection apart. Our desk review process involves conducting detailed assessments to evaluate projects against 6 quality principles: social harms, benefits, and environmental justice; environmental harms and benefits; additionality and baselines; measurement, monitoring, reporting, and verification; durability; and leakage. The result is a comprehensive report that assesses projects against these criteria, highlighting the project's overall quality, strengths, and weaknesses in a clear, succinct way that supports decision-making. 

Many of our reports dig even deeper. Our deep diligences assess both a project’s quality and its delivery risk. To evaluate delivery risk, we assess projects across 5 elements: technologic, economic, commercial, operational, and political. Deep diligence is conducted over 3-4 months, which includes weekly back-and-forth with the supplier and a site visit to understand all of the nuances of the project and validate developer claims on the ground. The resulting report not only documents a project's strengths and weaknesses, but also outlines risk mitigation measures and recommends improvements over time. 

Broader Access, Stronger Market 

Forward offtake demand in the CDR market has historically concentrated among a handful of large buyers, and as our 2026 State of the Voluntary Carbon Market report notes, diversifying that pool is essential to enabling the next generation of CDR supply. The Diligence Collection is built to support exactly that. By making the scientific rigor behind the world's largest CDR transactions available through a self-service platform, it opens credible procurement to organizations at any stage of purchasing. More buyers accessing high-quality, de-risked projects means more capital flowing to suppliers, more projects able to scale, and a more resilient market that doesn't depend on a small number of actors to function.

High-quality CDR supply is scarce, and the best projects are in high demand. The Diligence Collection gives you the foundation to act efficiently and with confidence, without starting from zero.

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Frequently Asked Questions

Who Can Access the Relae Diligence Collection?

The Diligence Collection is available to approved subscribers, including CDR buyers and investors seeking to more efficiently evaluate carbon removal projects. To preserve the independence and integrity of the Collection and protect proprietary diligence insights, access is not available to project developers or rating agencies.

How Is the Relae Diligence Collection Different From a Rating Agency or Market Intelligence Platform?

Most rating platforms optimize for quantity; we optimize for quality. Our process includes pathway-specific risk assessments and, in many cases, site visits from our in-house scientists, engineers, and technical experts—the same multidisciplinary team and judgment behind our own portfolio decisions and the procurement programs we support directly. The Collection also includes projects diligenced before they've received external ratings, giving you visibility into promising opportunities at the pre-commercialization stage.

Does Inclusion in the Relae Diligence Collection Mean Relae Endorses a Project?

Inclusion means a project was evaluated through our scientific diligence process and, at the time of review, met our Criteria for High-Quality Carbon Dioxide Removal. It reflects a positive diligence outcome based on the information available during the review and the project's stage of development at that time. As projects and market conditions evolve, we recommend considering whether updated diligence or additional evaluation is appropriate for your specific procurement or investment objectives.

Can I Request Diligence on a Project That Isn't Already in the Collection?

Yes. You can commission us to diligence a specific project based on your procurement or investment priorities. Whether it's later added to the Diligence Collection depends on a few factors beyond just meeting our quality bar, including consent from you as the commissioning buyer and approval from the project developer.

Key Takeaways

• Community opposition to data center development has become a national conversation, and state legislatures are now responding with a broad spectrum of policy responses to address constituent concerns.  
• Relae’s policy experts have identified six broad categories of policy responses: tax incentives, disclosure requirements, transparency rules, cost allocation, incentive clawbacks, and moratoria. In 2026, incentive bills are stalling while disclosure, cost allocation, and clawback bills are advancing.
• The shifting action of state legislatures across these categories can guide developers on the relative political openness or opposition to data center developments across the United States, and should inform site selection and investment decisions.
• Every state legislature will be back in session in 2027, including major data-center markets like North Dakota, Nevada, and Texas that sat out 2026, so this picture will keep changing.

Which States Are Getting Harder to Build In

Community concerns have translated into opposition, delaying, derailing, or altogether denying projects. Local debates over land, water, and electricity prices have moved into statehouses as a result. 

If you're trying to figure out "Which states are becoming harder (or easier) to site a data center in, and why?", the state legislature is where that answer is being written. Last year, we tracked the initial wave of state bills on data centers. This year, the volume of bills has grown. The policy categories we used last year still broadly hold, but the distribution of emphasis across these categories has shifted significantly.

Relae’s policy experts reviewed the bills introduced in 2026 legislative sessions related to data centers and identified six categories of policy responses available to a state: tax incentives (“reward it”), disclosure requirements (“review it”), transparency rules (“reveal it”), cost allocation (“shape it”), incentive clawbacks (“revoke it”), and moratoria (“stop it”). These categories do contain some overlap, but together they show a range of what legislatures are trying. 

Each response answers at least one of three questions local communities have been posing for over a year now: Who bears the costs of new generation, transmission, and other grid upgrades? What are constituents entitled to know about data center developments in their region? Who decides whether a project goes forward?

For each policy response, we selected at least one representative bill that is either most consequential financially or most impactful to developer timelines. Notably, states with significant data center development pressure, such as North Dakota, Nevada, and Texas, did not have regular sessions in 2026, meaning the scope of policy responses reflected here is not exhaustive. 

Six State Policy Responses to Watch for Data Center Siting and Investment

Which policy response a state reaches for, and how that bill fares in the legislative process, signals how politically open or resistant it currently is to new data center development. That political landscape should directly inform data center site selection and investment decisions - and it’s changing quickly.

1. Reward It: Data Center Tax Incentives and Subsidies 

These bills try to attract data centers by giving them a financial reason to locate in a state. We call this response "reward it." It typically means property tax exemptions, sales tax breaks on equipment, or reduced utility taxes, usually in exchange for a minimum investment and a job-creation commitment.

West Virginia Senate Bill 623, the “West Virginia-Powered Data Center Incentive Act,” would have exempted data center equipment from property taxes and cut business taxes for the utilities supplying power to the data center. To qualify, a data center would have needed to invest at least $50 million, create 50 jobs, and run on coal-generated electricity for at least 80% of its operational capacity. The bill died in committee without a vote, which is emblematic of how this category of bills fared in 2026. 

Relative to the approximately 50 bills introduced (and 9 passed) in 2025 that provided tax incentives for data centers, this category declined significantly in the 2026 session. Part of the drop off could also be a product of the current tax laws of many states, which already include substantial tax incentives for data centers. 

For developers, this is the category to watch shrink: fewer states are actively competing to hand out new incentives, so existing programs may be close to the extent of what's on offer going forward.

2. Review It: Data Center Disclosure Requirements 

Under what we call the "review it" response, these bills require specific information to be shared with regulators or grid operators before or while the project is built, usually about power demand, interconnection plans, or backup generation.

Pennsylvania House Bill 1834, the “Data Center Act,” would direct the state’s Public Utility Commission (PUC) to oversee commercial data centers with a peak demand of 25 megawatts or greater. It would require disclosure of information relating to interconnection requests as well as planned backup generation. It would also fast-track interconnection for facilities that bring incremental clean firm resources. That disclosure helps grid planners in PJM spot duplicate projects in their interconnection queue, while also helping state leaders to understand if projects in the state are in jeopardy of being lured elsewhere. The House passed the bill 104-95, and is awaiting action in the Senate. 

This category, which also includes bills that require disclosure of information around environmental impacts and power or water usage, has grown in 2026. Pennsylvania has been at the center of many discussions around data centers and utility affordability this year. Governor Josh Shapiro's initiative on utility affordability identifies data center load as the pressure point while a wider discussion evolves in PJM over capacity costs. 

3. Reveal It: Data Center Transparency Rules and NDA Bans 

This is a new category in 2026. We call it the "reveal it" response: bills that stop public officials from signing non-disclosure agreements about data center projects. The goal is to inform residents about who is behind a proposed facility and how much power it will use.

Ohio House Bill 695 would bar county commissioners, township trustees, village mayors, and council members from entering into nondisclosure agreements (NDAs) related to their official duties. It directly targets the NDAs that have kept local officials from telling residents who is behind a proposed project or how much power it would consume. The Ohio legislature is in session until December 17, and the bill is still awaiting action in committee. A similar bill in Pennsylvania, House Bill 2359, would tie NDA prohibitions to a data center sales tax exemption. That bill has passed the House and is also currently pending in the Senate. Separately, in August, Gov. Shapiro banned NDA use outright on any data center project the state oversees.

4. Shape It: Data Center Cost Allocation and Ratepayer Protection 

These bills aim to allocate more of the grid infrastructure costs associated with upgrades to the data center. New power lines, substations, and other transmission costs fall on the data center, not on everyone else's electric bill, under what we call the "shape it" response.

California Senate Bill 886, the California Technology Innovation and Ratepayer Protection Act, was signed into law by Governor Gavin Newsom on September 21, 2026, as part of a seven-bill data center package. It passed the Senate 28-10 and the Assembly 49-7. It requires the California PUC to establish or update electricity tariffs by January 1, 2028, for data centers entering new transmission-level interconnection agreements on or after January 1, 2027. Under it, developers bear the cost of transmission upgrades and face a 10-year early termination fee if they back out or fail to reach capacity. This is a strong template for keeping the costs of serving large loads from impacting retail ratepayers, and similar bills should be expected in other states in 2027. 

5. Revoke It: Data Center Incentive Clawbacks

_These bills take back or narrow tax breaks a state already granted (the "revoke it" response), usually once lawmakers start weighing what those incentives are actually costing the state against what they bought.

Washington Senate Bill 6231, signed into law by Governor Bob Ferguson in April, will remove the sales tax exemption for replacing or refurbishing existing server equipment. The category of bills revoking previous tax incentives for data center development and operation has grown substantially as more states are starting to reconsider the large incentives they put into place at the beginning of the data center boom. Over 50 bills in more than 20 states have sought to restrict data center incentives in 2026, including New Jersey Senate Bill S4390, which was signed into law in August.

6. Stop It: Data Center Development  Moratoria

These bills seek to temporarily restrict certain new data center development outright (the "stop it" response), usually for a fixed period while the state studies the impact on the grid, water use, or electricity rates.

New York Senate Bill S10642/Assembly Bill A11560, the Responsible Data Center Development Act, would impose a permit moratorium on data centers of 20 megawatts or more. It passed the legislature on June 4th and is awaiting action by Governor Kathy Hochul. If signed into law, it would be the first moratorium enacted through a legislature. Separately, Governor Hochul has issued an executive order to establish a temporary moratorium on data centers, though her order only applies to facilities of 50 megawatts or more. 

This category did not exist a year ago within state legislatures, but as public concern about data centers has grown, several moratorium bills have been introduced. Maine’s LD 307 passed through the state legislature and would have done the same, but was vetoed by Governor Janet Mills in April. In Texas, Governor Greg Abbott has issued orders to state agencies to halt data center approvals in ERCOT until audits can be completed, and in September, he expanded the pause to also cover a review of environmental permits. 

It is important to note that many of the moratoria put in place at the state level, whether through the legislature or via executive action, are temporary, usually one year in duration. Often, the moratoria being considered include a plan to study the impacts of data centers on communities and whether utility rates may rise.

What to Watch in 2027

The most consequential policies in 2026 didn’t come through legislatures. They came from executive action by the governors of New York and Texas, which went further than any legislature with respect to their financial and commercial impact. The outcome of the 2026 midterm elections will shape the appetite of both the legislative and executive branches for additional action. In addition, every state legislature will be in session in early 2027, including North Dakota, Nevada, and Texas, which all sat out 2026, so we expect significant policy developments to continue at the state level next year.

In legislatures, the pattern across all six policy responses points in the same direction: recent legislative activity suggests that some states are moving from attracting data center development through incentives toward imposing additional conditions, oversight requirements, or restrictions on new development. Fewer bills providing new incentives for data centers are being introduced or are stalling in legislatures, while bills on cost allocation, disclosure, incentive reduction, and permitting are advancing more successfully.

Map Your State's Regulatory Risk

Site selection and investment decisions increasingly hinge on which of these six responses a state is pulling, and how fast that can change. Talk to our Policy Advisory Team about what a state's current and pending legislation means for a specific project or portfolio.

Key Takeaways

• Speed to operation is the value proposition. While grid interconnection can take 3-5 years in constrained regions, hydrogen fuel cell systems can be deployed in a fraction of that time—a large advantage for operators racing to meet data center capacity demands.
• Hydrogen is moving beyond backup. Fuel cells could supply 6-15% of incremental data center power, functioning as primary or near-primary power rather than emergency standby.
• Higher fuel costs can be rational. When the alternative is a multi-year wait for grid power and the development loss that comes with it, paying a premium for hydrogen is better than falling behind.

The Grid Can’t Keep Up With Data Centers

The data center infrastructure buildout is moving at a pace the US power grid was never designed to accommodate. Cleanview tracks about 63 GW of operating US data center capacity and another 392 GW in planning, roughly six times what exists today. Developers in high-demand corridors—Northern Virginia, Central Texas, Phoenix—are finding that the grid can't deliver new capacity fast enough.

Interconnection queues now stretch 3-5 years in many regions, and that’s before accounting for permitting, transmission upgrades, and substation buildouts. For operators that need power online faster than the grid can deliver it, this timeline gap is a fundamental constraint on the business.

This mismatch between AI deployment, generator bottlenecks, and grid timelines is why hydrogen is entering the conversation as a viable power option for a growing subset of data center deployments, alongside natural gas with carbon capture, geothermal, and long-duration energy storage.

Hydrogen Fuel Cells: From Standby to Primary Power

For most of its history in data centers, hydrogen has been discussed as a cleaner replacement for diesel backup generators. That framing undersells the opportunity. 

The shift happening now is more fundamental: hydrogen fuel cells are being evaluated as primary or near-primary power sources for behind-the-meter and facilities that can’t wait for grid connection. Notably, many modern fuel cell systems—including solid oxide fuel cells—can run on natural gas today and transition to hydrogen as clean supply becomes available. Bloom Energy's 2024 deal with American Electric Power to provide up to 1 GW of fuel cells for data center power illustrates this approach: the systems will initially run on natural gas, with the capability to switch to 100% hydrogen in the future.

Furthermore, fuel cell systems are modular, can be deployed incrementally as load grows, and provide continuous power output. This is a promising path, and one that will scale only as fast as the fuel cell supply chain can keep up. Unlike solar or wind, fuel cells aren’t weather-dependent. Running on hydrogen, they produce zero direct emissions at the point of use. Running on natural gas, they still emit CO₂, but their higher efficiency gives them a lower carbon intensity than a comparable gas turbine.

Goldman Sachs estimates that fuel cells could supply 6-15% of incremental data center power (the estimate doesn't specify fuel mix, though most near-term deployments would run primarily on natural gas). This is a meaningful share of new capacity, driven largely by operators who face years-long waits for both grid connections and new gas turbines. Bloom Energy, whose fuel cell products serve data center applications, has been a notable outlier in an otherwise struggling hydrogen sector, with its stock rising sharply on strong revenue performance and growing investor enthusiasm around data center power demand.

Speed to power depends on the fuel. Solid oxide fuel cells run on pipeline natural gas today, so operators do not wait for a hydrogen supply chain. Bloom states it can deliver onsite power for an entire data center in as little as 90 days, with the ability to add modules as load grows under certain circumstances. In all but a few select locations, hydrogen comes later when the same systems switch fuels as clean supply scales. Projects that need hydrogen from day one face additional challenges. Limited hydrogen availability and supporting infrastructure across much of the US can undermine the potential speed advantage of hydrogen-dependent projects. Nevertheless, locations with suitable hydrogen supply and supporting infrastructure may offer viable near-term opportunities.

The Hydrogen Premium: When Paying More Makes Sense

Hydrogen-generated power is more expensive than other forms of electricity generation in most markets. The logistics penalty (including compression, transport, and storage) can push hydrogen from $4/kg at the production site to $8-16/kg delivered, making the economics look unfavorable on a simple $/MWh comparison. In practical terms, hydrogen at $4-6/kg translates to roughly $120-180/MWh on an energy-content basis (LHV). At a fuel cell electrical efficiency of around 50%—typical for solid oxide systems—the effective cost of electricity rises to approximately $240-360/MWh for co-located production, compared to $40-60/MWh for natural gas fuel cells, $51-129/MWh for gas combined cycle, and $144-276/MWh for gas peakers. Operators can improve hydrogen economics by co-locating with production, avoiding the logistics penalty that can double or quadruple delivered costs.

While expensive, this cost comparison misses the central point. The relevant question is not whether hydrogen is cheaper than grid power, but whether it is better than having no access to power at all.

For an operator with signed contracts and a 100 MW facility sitting idle during a multi-year interconnection queue, the opportunity cost is substantial. At average US wholesale colocation rates (~$196/kW/month - a record high), a facility of that size represents roughly $235 million per year in potential revenue—meaning even a single year of delay can outweigh years of hydrogen fuel premiums. 

The Inflation Reduction Act’s 45V Production Tax Credit further compresses the gap, offering up to $3/kg for clean hydrogen production—but projects must begin construction by December 31, 2027, to qualify. That deadline adds urgency to what’s already a time-sensitive calculus.

Reframing the Cost Debate for Speed-to-Power

The debate about whether hydrogen is cost-competitive with grid power misses the strategic challenge facing data center operators today: the fastest path to reliable, clean power. Hydrogen can play a consequential role in that timeline in some markets.

Assessing that requires modeling the full picture: grid interconnection timelines, hydrogen supply chain costs at a specific location, the 45V credit’s impact on project economics, and how hydrogen compares to batteries and other bridging technologies for a data center’s particular load profile.

Relae’s advisory team helps data center operators and technology companies evaluate these tradeoffs with rigorous, independent analysis. If speed to operation is a factor in your energy planning, let’s talk.

Frequently Asked Questions

How much faster is hydrogen fuel cell deployment than waiting for grid interconnection?
Grid interconnection in constrained regions can take 3-5 years once permitting, transmission upgrades, and substation buildouts are factored in. Fuel cell systems, especially those that start on natural gas and then transition to hydrogen, can be deployed in a fraction of that time. They are modular and can be installed and scaled incrementally as a facility’s load grows, though the pace depends on equipment and fuel supply.

If hydrogen costs more than grid power, why would an operator choose it?
For an operator with a 100 MW facility sitting idle during a multi-year interconnection queue, the lost revenue—roughly $235 million a year at average US wholesale colocation rates—can outweigh years of hydrogen’s fuel premium. That makes the higher cost a rational tradeoff against a multi-year wait for grid power, not just an expensive alternative to it.

Do hydrogen fuel cell systems have to run on pure hydrogen from day one?
No. Many modern fuel cell systems, including solid oxide fuel cells, can run on natural gas today and transition to hydrogen as clean supply becomes available. Bloom Energy’s up to 1 GW agreement with American Electric Power follows this model: the systems start on natural gas, with the capability to switch to 100% hydrogen as the hydrogen supply chain matures.